Oxidizing gasses for carbon dioxide-based fracturing fluids

ABSTRACT

Unconventional hydrocarbon source rock reservoirs can contain the organic material kerogen, intertwined with the rock matrix. The kerogen can alter the tensile strength of the rock and contribute to higher fracture energy needs. To degrade kerogen and other organic materials, oxidizing gasses are dissolved in carbon dioxide (CO 2 ) which is then used as part of a fracturing fluid. The oxidizing gasses can be dissolved directly in the CO 2  or generated in situ using precursors.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of and claims priority to U.S. patentapplication Ser. No. 16/938,679, filed on Jul. 24, 2019, which claimspriority to U.S. Provisional Patent Application Ser. No. 62/878,115,filed on Jul. 24, 2019, the entire contents of which are incorporated byreference herein.

TECHNICAL FIELD

This document relates to methods and compositions used in treatingsubterranean formations for enhancing hydrocarbon fluid recovery.

BACKGROUND

Unconventional hydrocarbon source rock reservoirs are formations withtrapped hydrocarbons in which the hydrocarbon mobility is limited due tothe nano-pore throat size, and the low formation permeability.Extraction of hydrocarbons from such reservoirs typically involvesincreasing the surface area of flow by hydraulic fracturing of the rockformation. The pressure of the fracturing fluid propagates the createdfracture, while pumping slurry and proppants keeps the fracture openafter shutting off the hydraulic pumping. Unconventional reservoirs havethe organic polymeric material kerogen intertwined with the granularrock matrix. The kerogen can alter the tensile strength of the rock andas a result, contribute to greater fracturing energy needed to propagatethe fracture than in formations without the kerogen material. Further,the ductile nature of the organic matter may lead to premature fractureclosure and proppant embedment issues that reduce the long-termproductivity of the fractured formation. Also, treating kerogen on thefractured faces enhances hydraulic conductivity of the opened faces andthus adds to the longevity of the fracture and to hydrocarbonproductivity.

SUMMARY

This disclosure describes the use of oxidizing gasses in combinationwith carbon dioxide (CO₂)-based hydraulic fracturing fluids.

The following units of measure have been mentioned in this disclosure:

Unit of Measure Full form cm centimeter mL milliliter mmol millimole psipounds per square inch ° C. degrees Celsius

Certain aspects of the subject matter described in this disclosure canbe implemented as a method for treating kerogen in a subterranean zone.A composition that includes carbon dioxide and an oxidizing gas isplaced in the subterranean zone. Organic matter, for example, kerogen,in the subterranean zone is treated with the composition.

An aspect combinable with any of the other aspects includes thefollowing features. The composition is flowed to a location in thesubterranean zone to place the composition in the subterranean zone.

An aspect combinable with any of the other aspects includes thefollowing features. The oxidizing gas includes at least one of chlorinedioxide (ClO₂), chlorine gas (Cl₂), bromine gas (Br₂), fluorine gas(F₂), chlorine monofluoride (ClF), oxygen gas (O₂), ozone (O₃), nitrousoxide (N₂O), nitric oxide (NO), or nitrogen dioxide (NO₂).

An aspect combinable with any of the other aspects includes thefollowing features. The oxidizing gas is supplied by an oxidizing gasstream.

An aspect combinable with any of the other aspects includes thefollowing features. The oxidizing gas is generated in situ.

An aspect combinable with any of the other aspects includes thefollowing features. Precursors are provided, including a first precursorand a second precursor. The first precursor compound is injected intothe composition. A spacer amount of carbon dioxide is pumped into thecomposition, for example, after injecting the first precursor. Thesecond precursor compound is injected into the composition, for example,after pumping the spacer amount of carbon dioxide. The first and secondprecursor compounds react to generate the oxidizing gas.

An aspect combinable with any of the other aspects includes thefollowing features. The precursors include a chlorite and an oxidizingagent.

An aspect combinable with any of the other aspects includes thefollowing features. The precursors include a chlorate and a reducingagent.

An aspect combinable with any of the other aspects includes thefollowing features. The precursors include an acid.

An aspect combinable with any of the other aspects includes thefollowing features. At least one of a proppant, a viscosifier, a breakeror a fracturing additive is added to the composition.

An aspect combinable with any of the other aspects includes thefollowing features. The viscosifier includes at least one ofbiopolymers, synthetic polymers, or fluoropolymers or combinationthereof.

An aspect combinable with any of the other aspects includes thefollowing features. The breaker includes at least one of bromate,chlorate, chlorite, hypochlorite, persulfate, perborate, peroxide,percarbonate, nitrate, nitrite, or combinations thereof.

An aspect combinable with any of the other aspects includes thefollowing features. The proppant includes at least one of sand,resin-coated proppant, epoxy-coated proppant, microproppant, ornanoproppant.

An aspect combinable with any of the other aspects includes thefollowing features. The fracturing additive includes at least one ofscale inhibitors, corrosion inhibitors, clay swelling inhibitors, ironcontrol agents, flowback aids, biocides, buffer, crosslinker, fluid lossadditives, or diverters.

An aspect combinable with any of the other aspects includes thefollowing features. The composition is pressurized. The pressurizedcomposition is injected into a wellbore formed in the subterranean zone.The injection pressure is maintained for between 2 to 20 hours. Thecomposition is penetrated into kerogen-containing source rock in thesubterranean zone. Flowback of the composition is induced. Unspentoxidizer is scrubbed from the flowback fluid.

The details of one or more implementations of the disclosure are setforth in the accompanying drawings and the description that follows.Other features, objects, and advantages of the disclosure will beapparent from the description and drawings, and from the claims.

DESCRIPTION OF DRAWINGS

FIG. 1 shows an example of a fracture treatment for a well.

FIG. 2A is an example of a schematic of a gas mixing process.

FIG. 2B is an example of a schematic of a gas mixing process.

FIGS. 3-6 are scanning electron microscope (SEM) images of a sample ofshale before and after treatment with bromine and supercritical carbondioxide.

FIG. 7 is an SEM image of the shale after treatment with bromine andsupercritical carbon dioxide.

FIG. 8A is a backscatter-electron map (top left), andelectron-dispersive X-Ray spectroscopic (EDS) element maps for oxygen(top right), carbon (bottom left), and bromine (bottom right).

FIG. 8B is the EDS spectrum for the shale sample.

FIG. 9 is a flow chart of an example of a method for treating a well.

FIG. 10 is a flow chart of an example of a method for treating a well.

Like reference symbols in the various drawings indicate like elements.

DETAILED DESCRIPTION

Reference will now be made in detail to certain embodiments of thedisclosed subject matter, examples of which are illustrated in part inthe accompanying drawings. While the disclosed subject matter will bedescribed in conjunction with the enumerated claims, it will beunderstood that the exemplified subject matter is not intended to limitthe claims to the disclosed subject matter.

Provided in this disclosure, in part, are methods, compositions, andsystems for degrading organic matter, for example kerogen, bitumen, orpyrobitumen, in a subterranean formation. Further, these methods,compositions, and systems allow for increased hydraulic fracturingefficiencies in subterranean formations, such as unconventional sourcerock reservoirs.

In some implementations, hydraulic fracturing is performed using ahydraulic fracturing fluid that includes CO₂, which can be in gaseousstate, in supercritical state, in liquid state or a combination of them.In order to treat and degrade kerogen present in unconventional rocksources, the fracturing fluid also includes oxidizing gasses soluble inCO₂. These soluble oxidizing gasses include, but are not limited to,oxygen gas (O₂), ozone (O₃), fluorine gas (F₂), chlorine gas (Cl₂),bromine gas (Br₂), chlorine monofluoride (ClF), chlorine dioxide (ClO₂),nitrous oxide (N₂O), nitric oxide (NO), and nitrogen dioxide (NO₂).These gasses can be dissolved directly in the CO₂ or generated in situby combining chemical precursors in the fracturing fluid. For example,ozone (O₃) can be generated on site from pure oxygen gas or from air.The O₃ can then be injected directly into the CO₂ as described laterwith reference to FIGS. 2A and 2B. Similarly, chlorine dioxide (ClO₂)can be generated on-site with commercially available equipment, mixedwith air, and added directly to the CO₂ via an oxidizing gas stream asdescribed later with reference to FIGS. 2A and 2B.

Alternatively or in addition, the oxidizing gas can be generated insitu. First, a first precursor compound is injected into the CO₂, whichis pumped into the wellbore. Next, a spacer amount of CO₂ is pumped intothe wellbore. Then, a second precursor compound is injected into theCO₂, which is pumped into the wellbore. The spacer amount of CO₂ ensuresthat the precursors do not prematurely react to form the oxidizing gasbefore reaching a pre-determined depth within the wellbore.

The oxidizing gasses generated in situ can be prepared by one or more ofseveral techniques. For example, the chlorite can be combined with anacid, for example, hydrochloric acid (HCl) or hydrosulfuric acid(H₂SO₄). In some implementations, the in situ preparation of chlorinedioxide can occur using a chlorite and an oxidizing agent as theprecursors. In some implementations, the oxidizing agent can be chlorinegas (Cl₂) or hypochlorite (ClO⁻). The oxidizing gas can also begenerated in situ using a chlorite, an oxidizing agent, and an acid.Suitable acids include citric acid, oxalic acid, HCl or H₂SO₄.

Alternatively, the oxidizing gas can be generated using a chlorate and areducing agent as the precursors. Suitable reducing agents includemethanol, hydrogen peroxide, HCl, or sulfur dioxide. In addition, theoxidizing gas can also be generated in situ using a chlorate, a reducingagent, and an acid. Suitable acids include HCl and H₂SO₄.

Example 1: Generation of chlorine dioxide by oxidation of sodiumchlorite, for example the reaction of sodium chlorite (NaClO₂) andhydrochloric acid (HCl):

$\begin{matrix}\left. {{2\mspace{14mu}{NaClO}_{2}} + {Cl}_{2}}\rightarrow{{2\mspace{14mu}{ClO}_{2}} + {2\mspace{14mu}{NaCl}}} \right. & {{eq}.\mspace{14mu} 3}\end{matrix}$

Example 2: Generation of chlorine dioxide by oxidation of sodiumchlorite, using hydrochloric acid and sodium hypochlorite:

$\begin{matrix}\left. {{2\mspace{14mu}{KClO}_{3}} + {2\mspace{14mu} H_{2}C_{2}O_{4}}}\rightarrow{{2\mspace{14mu}{ClO}_{2}} + {2\mspace{14mu}{CO}_{2}} + {2\mspace{14mu} H_{2}O}} \right. & {{eq}.\mspace{14mu} 4}\end{matrix}$

Example 3: Generation of chlorine dioxide by oxidation of sodiumchlorite with chlorine gas:

$\begin{matrix}\left. {{5\mspace{14mu}{NaClO}_{2}} + {4\mspace{14mu}{HCl}}}\rightarrow{{5\mspace{14mu}{NaCl}} + {4\mspace{14mu}{ClO}_{2}} + {2\mspace{14mu} H_{2}O}} \right. & {{eq}.\mspace{14mu} 1}\end{matrix}$

Example 4: Generation of chlorine dioxide by reduction of sodiumchlorate, for example, the reduction of sodium chlorate with oxalicacid:

$\begin{matrix}\left. {{2\mspace{14mu}{ClO}_{3}^{-}} + {2\mspace{14mu}{Cl}^{-}} + {4\mspace{14mu} H^{+}}}\rightarrow{{2\mspace{14mu}{ClO}_{2}} + {Cl}_{2} + {2\mspace{14mu} H_{2}O}} \right. & {{eq}.\mspace{14mu} 5}\end{matrix}$

Example 5: Generation of chlorine dioxide by reduction of sodiumchlorate with hydrochloric acid:

$\begin{matrix}\left. {{2\mspace{14mu}{NaClO}_{2}} + {2\mspace{14mu}{HCl}} + {NaOCl}}\rightarrow{{2\mspace{14mu}{ClO}_{2}} + {3\mspace{14mu}{NaCl}} + {H_{2}O}} \right. & {{eq}.\mspace{14mu} 2}\end{matrix}$

In some implementations, the fracturing fluid can include additionalfracturing additives. These fracturing additives include but are notlimited to proppant, viscosifiers, and breakers. Proppant types includebut are not limited to sand, resin-coated sand, ceramic, resin-coatedceramic, bauxite, glass, walnut hull, resin-coated walnut hull,microproppant or nanoproppant (of sand or ceramic). The viscosifiersinclude but are not limited to biopolymers, synthetic polymers,fluoropolymers, and combinations thereof. The breakers include but arenot limited to bromate, chlorate, chlorite, hypochlorite, persulfate,perborate, peroxide, percarbonate, nitrate, nitrite, and combinationsthereof.

In some implementations, the composition can be pressurized to thebreakdown pressure of the formation and injected into the wellbore. Theinjection pressure is then maintained for 2 to 20 hours. The compositionpenetrates into the source rock, where the oxidizer reacts with organicmaterial, for example, kerogen, to form byproducts. Next, the CO₂,organic material byproducts, and unspent oxidizer flow back to thesurface. The organic material byproducts may be soluble in CO₂ andreservoir hydrocarbons. After flowback, the unspent oxidizer can bescrubbed allowing re-use of the oxidizer. However, it is possible thatall of the oxidizing gas can be consumed downhole, negating the need fordisposal or flowback treatment.

The compositions described within this disclosure can be used to breakdown, dissolve, or remove all or parts of the kerogen or other organicmaterial in or near the areas to be hydraulically fractured in asubterranean formation. Using a composition described within thisdisclosure, the kerogen or other organic matter (or both) can be brokendown by, for example, pumping the composition into a subterraneanformation.

The concentration of the components of the composition (for example, theoxidizers or additives) can depend on the quantity of kerogen or otherorganic matter in the reservoir rock. For example, the concentration ofthe oxidizer in the composition can be increased in response toformations with a greater quantity of organic matter to be removed orpartially removed.

The composition can further include a fracturing fluid or a pad fluidand can be pumped into a subterranean formation before fracturing,during fracturing, or both. In some embodiments, the release of thecomposition including oxidizers can be delayed from a carrier fluid. Adelayed release of the composition can decrease corrosion issues (forexample, in metal tubing in the wellbore through which the fluids aredelivered to the formation) and polymer degradation in the treatingfluid. The polymers subject to degradation include, for example,friction reducers or other polymers used in hydraulic fracturing.

FIG. 1 illustrates an example of a fracture treatment 10 for a well 12.The well 12 can be associated with a reservoir or formation 14, forexample, an unconventional reservoir in which recovery operations inaddition to conventional recovery operations are practiced to recovertrapped hydrocarbons. Examples of unconventional reservoirs includetight-gas sands, gas and oil shales, coalbed methane, heavy oil and tarsands, and gas-hydrate deposits. In some implementations, the formation14 includes an underground formation of naturally fractured rockcontaining hydrocarbons (for example, oil, gas, or both). For example,the formation 14 can include a fractured shale. In some implementations,the well 12 can intersect other suitable types of formations 14,including reservoirs that are not naturally fractured in any significantamount.

The well 12 can include a well bore 20, casing 22 and well head 24. Thewell bore 20 can be a vertical or deviated bore. The casing 22 can becemented or otherwise suitably secured in the well bore 12. Perforations26 can be formed in the casing 22 at the level of the formation 14 toallow oil, gas, and by-products to flow into the well 12 and be producedto the surface 25. Perforations 26 can be formed using shape charges, aperforating gun or otherwise.

For the fracture treatment 10, a work string 30 can be disposed in thewell bore 20. The work string 30 can be coiled tubing, sectioned pipe orother suitable tubing. A fracturing tool 32 can be coupled to an end ofthe work string 30. Packers 36 can seal an annulus 38 of the well bore20 above and below the formation 14. Packers 36 can be mechanical, fluidinflatable or other suitable packers.

One or more pump trucks 40 can be coupled to the work string 30 at thesurface 25. The pump trucks 40 pump fracture fluid 58 down the workstring 30 to perform the fracture treatment 10 and generate the fracture60. The fracture fluid 58 can include a fluid pad, proppants and a flushfluid. The pump trucks 40 can include mobile vehicles, equipment such asskids or other suitable structures.

One or more instrument trucks 44 can also be provided at the surface 25.The instrument truck 44 can include a fracture control system 46 and afracture simulator 47. The fracture control system 46 monitors andcontrols the fracture treatment 10. The fracture control system 46 cancontrol the pump trucks 40 and fluid valves to stop and start thefracture treatment 10 as well as to stop and start the pad phase,proppant phase and flush phase of the fracture treatment 10. Thefracture control system 46 communicates with surface and subsurfaceinstruments to monitor and control the fracture treatment 10. In someimplementations, the surface and subsurface instruments may includesurface sensors 48, down-hole sensors 50 and pump controls 52.

A quantity of energy applied by the fracture control system 46 togenerate the fractures 60 in the reservoir or formation 14 can beaffected not only by the properties of the reservoir rock in theformation but also by the organic matter (for example, kerogen 75)intertwined within the rock matrix. As discussed within this disclosure,kerogen or other organic material in a reservoir can increase thetensile strength of the rock, for example, by as much as 100-fold,resulting in a corresponding increase in the ultimate tensile strengthof the rock. The rock-organic material combination has a higher modulusof toughness than rock alone. Therefore fracturing rock-organic materialrequires more energy than fracturing only rock. Moreover, the presenceof organic material in the reservoir can affect production as well. Forexample, elastic properties of kerogen can prematurely close fracturesresulting in decrease in production. The ductile kerogen can alsoenhance proppant embedment on the fracture faces which reduces fractureconductivity and long-term productivity. Accordingly, the presence ofkerogen in a subterranean formation can decrease an efficiency ofhydraulic fracturing treatments.

This specification describes compositions 81 to degrade the kerogen orother organic material encountered in subterranean formations, such asat the openings of cracks in hydraulic fractures. The compositions caninclude hydraulic fracturing fluids (for example, the fracture fluid 58)and flowed through the subterranean formation (for example, areservoir). As or after the organic material is degraded, a quantity ofenergy to generate and propagate fractures in the subterranean formation(for example, a reservoir) can decrease, thereby increasing anefficiency (for example, cost, time, long-term effect) of the fracturingprocess. In addition, fracture length and formation surface exposureafter wellbore shut-in can be greater than corresponding parameters inreservoirs in which the kerogen has not been degraded. In addition,removing or partially removing the organic matter from the near fracturezone can decrease the propensity for the fractures to close (reheal)after the pressure is released from pumping the fracturing, therebyimproving the overall productivity of the well.

FIG. 2A is an example of a schematic of a gas mixing process. In someimplementations, CO₂ 202 is flowed through a first fluid flow pathway204 (for example, an elongate tubular member) into a mixer 206. Anoxidizing gas stream 208 is flowed through a second fluid flow pathway210 (for example, an elongate tubular member) into the mixer 206. Insome implementations, the mixer 206 is operated to dissolve theoxidizing gas stream 208 in the CO₂ 202. The resulting mixture is flowedinto a third fluid flow pathway 212 (for example, an elongate tubularmember) to be injected into the wellbore (not shown).

FIG. 2B is an example of a schematic of a gas mixing process. Thefeatures of FIG. 2B are substantially the same as those of FIG. 2A. Inplace of an oxidizing gas stream 208, an ozone generator 214 can bepositioned in or otherwise fluidically coupled to the second fluid flowpathway 210. Oxygen or air 216 can be flowed into the ozone generator214 to generate ozone 218. The generated ozone 218 can be mixed with theCO₂ 202 in the mixer 206. The resulting mixtures is flowed into a thirdfluid flow pathway 212 (for example, an elongate tubular member) to beinjected into the wellbore (not shown).

FIGS. 3-6 are scanning electron microscope (SEM) images of a sample ofshale rock before (left) and after (right) treatment with bromine gasand CO₂. FIG. 7 is an SEM image of the shale rock after treatment withbromine gas and CO₂.

Table 1 shows mineralogy of polished shale sample before treatment.

TABLE 1 Mineralogy of polished shale sample before treatment MineralPercent abundance Quartz 30 Albite 9 Orthoclase 2 Chlorite 9 Illite/Mica35 Illite/Smectite 7 Pyrite Trace Anatase 2 Siderite 5 Kaolinite 1Gypsum 0 Dolomite 0

The sample of the mineralogical composition was cut into a 1 cm×1 cm×1.5cm rectangular prism and polished with a broad ion-beam to create a flatsurface. Scanning electron microscope (SEM) images of the shale wereobtained before treatment. The shale was then placed in a 750 mLhigh-pressure autoclave composed of corrosion resistant metal alloy.Next, 3 mL of bromine (60 mmol) was added to the autoclave. Theautoclave was then filled with liquid carbon dioxide (CO₂) at 800 psi.The autoclave was then sealed and heated to 150° C. at a pressure of2600 psi for 20 hours. The autoclave was then allowed to cool anddepressurize. The sample was then washed with 10 mL of deionized waterto remove sodium bromide (NaBr) salt crystals from the surface of therock. Next, SEM images were obtained after treatment and compared toimages taken before treatment (FIGS. 3-6 ). In the treated sample, sitesformerly occupied by NaBr crystals are seen in halos of brominatedkerogen tar (FIG. 5 right; FIG. 6 right). The presence of NaBr isattributable to trace water in the system and interfacial condensationof water at the rock surface upon depressurization. In the treatedsample, brominated kerogen tar was found to have upwelled in fissures inthe shale (FIG. 3 , B; FIG. 5 right) and spatter of brominated kerogentar is observed around fissures generated through the treatment process(FIG. 4 , B; FIG. 7 ). In the treated sample, brominated kerogen tar isalso visible on the surface of the treated sample (FIG. 8A). Inaddition, pyrite and iron-containing rock was observed to have beendissolved away from the shale (FIG. 3 , A; FIG. 4 , A; FIG. 5 , A).

FIG. 8A is a backscatter-electron map (top left), andelectron-dispersive X-Ray spectroscopic (EDS) element maps for oxygen(top right), carbon (bottom left), and bromine (bottom right). FIG. 8Bis the EDS spectrum for the sample (bottom), which confirms the presenceof bromine.

FIG. 9 is a flowchart of an example of a process 300 for degradingorganic material in a subterranean zone. The process can be implementedusing different types of hydraulic fracturing fluids. At 301, an organicmatter-degrading composition (for example, a composition including anoxidizer, such as chlorine dioxide) is mixed with a fluid. The fluid canbe a hydraulic fracture fluid or a pad fluid that is flowed into thereservoir before the hydraulic fracture fluid (or both). At 303,additives, including friction reducers, viscosifiers, breakers,proppant, scale inhibitors, clay swelling inhibitors, corrosioninhibitors, iron control agents, flowback aid, or biocides, can be addedto the mixture of the composition and fluid. At 305, the composition ispressurized. At 307, the fluid (with the organic matter-degradingcomposition) is pumped into the reservoir as part of a hydraulicfracture treatment. As described previously, the organic matter degradesupon reacting with the composition. At 309, the composition, byproducts,and unspent oxidizer flowback to the surface. At 311, unspent oxidizermay be scrubbed for re-use.

FIG. 10 is a flowchart of an example of a process 400 for degradingorganic material in a subterranean zone. The process can be implementedusing different types of hydraulic fracturing fluids. This process 400includes the use of precursors to generate the oxidizing gas in situ. At401, a first precursor is mixed with carbon dioxide. At 403, the firstprecursor and carbon dioxide are pumped into the wellbore. At 405, aspacer amount of carbon dioxide is pumped into the wellbore. At 407, asecond precursor is mixed with carbon dioxide. At 409, the secondprecursor and carbon dioxide are pumped into the wellbore. At 411,additives, including friction reducers, viscosifiers, breakers,proppant, scale inhibitors, clay swelling inhibitors, corrosioninhibitors, iron control agents, flowback aid, or biocides, can be addedto the mixture or fluid. At 413, the composition is pressurized. At 415,the composition is pumped into the reservoir as part of a hydraulicfracture treatment. As described previously, the precursors react togenerate an oxidizing gas in situ. The kerogen and organic matterdegrade upon reacting with the composition containing the in situgenerated gas. At 417, the composition, byproducts, and unsepentoxidizer flowback to the surface. At 419, unspent oxidizer may bescrubbed for re-use.

The term “about” as used in this disclosure can allow for a degree ofvariability in a value or range, for example, within 10%, within 5%, orwithin 1% of a stated value or of a stated limit of a range.

The term “substantially” as used in this disclosure refers to a majorityof, or mostly, as in at least about 50%, 60%, 70%, 80%, 90%, 95%, 96%,97%, 98%, 99%, 99.5%, 99.9%, 99.99%, or at least about 99.999% or more.

The term “solvent” as used in this disclosure refers to a liquid thatcan dissolve a solid, another liquid, or a gas to form a solution.Non-limiting examples of solvents are silicones, organic compounds,water, alcohols, ionic liquids, and supercritical fluids.

The term “room temperature” as used in this disclosure refers to atemperature of about 15 degrees Celsius (° C.) to about 28° C.

The term “downhole” as used in this disclosure refers to under thesurface of the earth, such as a location within or fluidly connected toa wellbore.

As used in this disclosure, the term “fracturing fluid” refers to fluidsor slurries used downhole during fracturing operations.

As used in this disclosure, the term “fluid” refers to liquids and gels,unless otherwise indicated.

As used in this disclosure, the term “subterranean material” or“subterranean zone” refers to any material under the surface of theearth, including under the surface of the bottom of the ocean. Forexample, a subterranean zone or material can be any section of awellbore and any section of a subterranean petroleum- or water-producingformation or region in fluid contact with the wellbore. Placing amaterial in a subterranean zone can include contacting the material withany section of a wellbore or with any subterranean region in fluidcontact with the material. Subterranean materials can include anymaterials placed into the wellbore such as cement, drill shafts, liners,tubing, casing, or screens; placing a material in a subterranean zonecan include contacting with such subterranean materials. In someexamples, a subterranean zone or material can be any downhole regionthat can produce liquid or gaseous petroleum materials, water, or anydownhole section in fluid contact with liquid or gaseous petroleummaterials, or water. For example, a subterranean zone or material can beat least one of an area desired to be fractured, a fracture or an areasurrounding a fracture, and a flow pathway or an area surrounding a flowpathway, in which a fracture or a flow pathway can be optionally fluidlyconnected to a subterranean petroleum- or water-producing region,directly or through one or more fractures or flow pathways.

As used in this disclosure, “treatment of a subterranean zone” caninclude any activity directed to extraction of water or petroleummaterials from a subterranean petroleum- or water-producing formation orregion, for example, including drilling, stimulation, hydraulicfracturing, clean-up, acidizing, completion, cementing, remedialtreatment, abandonment, aquifer remediation, identifying oil richregions via imaging techniques, and the like.

A number of implementations of the disclosure have been described.Nevertheless, it will be understood that various modifications may bemade without departing from the spirit and scope of the disclosure.

What is claimed is:
 1. A method for treating kerogen in a subterraneanzone, the method comprising: placing a composition in the subterraneanzone, the composition comprising carbon dioxide, and an oxidizing gas,wherein the oxidizing gas is bromine gas (Br₂), and treating the kerogenin the subterranean zone with the composition.
 2. The method of claim 1,wherein placing the composition comprises flowing the composition to alocation in the subterranean zone.
 3. The method of claim 1, wherein theoxidizing gas further comprises at least one of chlorine dioxide (ClO₂),chlorine gas (Cl₂), fluorine gas (F₂), chlorine monofluoride (ClF),oxygen gas (O₂), ozone (O₃), nitrous oxide (N₂O), nitric oxide (NO),nitrogen dioxide (NO₂), or mixtures thereof.
 4. The method of claim 1,further comprising supplying the oxidizing gas by an oxidizing gasstream.
 5. The method of claim 1, further comprising: adding at leastone of a proppant, a viscosifier, a breaker, or a fracturing additive tothe composition.
 6. The method of claim 5, wherein the viscosifier isadded, and wherein the viscosifier comprises at least one ofbiopolymers, synthetic polymers, or fluoropolymers.
 7. The method ofclaim 5, wherein the breaker is added, and wherein the breaker comprisesat least one of bromate, chlorate, chlorite, hypochlorite, persulfate,perborate, peroxide, percarbonate, nitrate, nitrite, or combinationsthereof.
 8. The method of claim 5, wherein the proppant is added, andwherein the proppant comprises at least one of sand, resin-coated sand,ceramic, resin-coated ceramic, bauxite, glass, walnut hull, resin-coatedwalnut hull, microproppant or nanoproppant.
 9. The method of claim 5,wherein the fracturing additive is added, and wherein the fracturingadditive comprises at least one of scale inhibitors, corrosioninhibitors, clay swelling inhibitors, iron control agents, flowbackaids, biocides, fluid loss additive, buffer, or diverter.
 10. The methodof claim 1, further comprising pressurizing the composition to aninjection pressure; injecting the composition into a wellbore formed inthe subterranean zone; maintaining the injection pressure for 2 to 20hours: penetrating the composition into kerogen-containing source rockin the subterranean zone; inducing flowback of the composition; andscrubbing unspent oxidizer.